Water based completion and displacement fluid and method of use

ABSTRACT

A method of cleaning a wellbore prior to the production of oil or gas is disclosed, wherein the wellbore has been drilled with an invert emulsion drilling mud that forms an invert emulsion filter cake. The method may include the steps of circulating a breaker fluid into the wellbore, where the breaker fluid includes an aqueous fluid, a water soluble polar organic solvent, a hydrolysable ester of a carboxylic acid, and a weighting age, and where the hydrolysable ester is selected so that upon hydrolysis an organic acid is released and the invert emulsion of the filter cake breaks.

This application claims the priority under 35 U.S.C. §119 to U.S.application Ser. No. 60/668,485 filed Apr. 5, 2005. That application isincorporated by reference in its entirety.

BACKGROUND OF INVENTION

1. Field of the Invention

Embodiments relate generally to wellbore fluids. More specifically,embodiments relate to displacement and chemical breaker fluids.

2. Background Art

During the drilling of a wellbore, various fluids are typically used inthe well for a variety of functions. The fluids may be circulatedthrough a drill pipe and drill bit into the wellbore, and then maysubsequently flow upward through wellbore to the surface.

During this circulation, the drilling fluid may act to remove drillcuttings from the bottom of the hole to the surface, to suspend cuttingsand weighting material when circulation is interrupted, to controlsubsurface pressures, to maintain the integrity of the wellbore untilthe well section is cased and cemented, to isolate the fluids from theformation by providing sufficient hydrostatic pressure to prevent theingress of formation fluids into the wellbore, to cool and lubricate thedrill string and bit, and/or to maximize penetration rate.

In most rotary drilling procedures the drilling fluid takes the form ofa “mud,” i.e., a liquid having solids suspended therein. The solidsfunction to impart desired rheological properties to the drilling fluidand also to increase the density thereof in order to provide a suitablehydrostatic pressure at the bottom of the well. The drilling mud may beeither a water-based or an oil-based mud.

Drilling muds may consist of polymers, biopolymers, clays and organiccolloids added to a water-based fluid to obtain the required viscous andfiltration properties. Heavy minerals, such as barite or calciumcarbonate, may be added to increase density. Solids from the formationare incorporated into the mud and often become dispersed in the mud as aconsequence of drilling. Further, drilling muds may contain one or morenatural and/or synthetic polymeric additives, including polymericadditives that increase the rheological properties (e.g., plasticviscosity, yield point value, gel strength) of the drilling mud, andpolymeric thinners and flocculents.

Polymeric additives included in the drilling fluid may act as fluid losscontrol agents. Fluid loss control agents, such as starch, prevent theloss of fluid to the surrounding formation by reducing the permeabilityof filter cakes formed on the newly exposed rock surface. In addition,polymeric additives are employed to impart sufficient carrying capacityand thixotropy to the mud to enable the mud to transport the cuttings upto the surface and to prevent the cuttings from settling out of the mudwhen circulation is interrupted.

Many drilling fluids may be designed to form a thin, low-permeabilityfilter cake to seal permeable formations penetrated by the drill bit.The filter cake is essential to prevent or reduce both the loss offluids into the formation and the influx of fluids present in theformation. Upon completion of drilling, the filter cake may stabilizethe wellbore during subsequent completion operations such as placementof a gravel pack in the wellbore. Filter cakes often comprise bridgingparticles, cuttings created by the drilling process, polymericadditives, and precipitates. One feature of a drilling fluid is toretain these solid and semi-solid particles as a stable suspension, freeof significant settling over the time scale of drilling operations.

The selection of the type of drilling fluid to be used in a drillingapplication involves a careful balance of both the good and badcharacteristics of the drilling fluids in the particular application andthe type of well to be drilled. The primary benefits of selecting anoil-based drilling fluid, also known as an oil-based mud, include:superior hole stability, especially in shale formations, formation of athinner filter cake than the filter cake achieved with a water-basedmud, excellent lubrication of the drilling string and downhole tools,and penetration of salt beds without sloughing or enlargement of thehole, as well as other benefits that should be known to one of skill inthe art.

An especially beneficial property of oil-based muds is their excellentlubrication qualities. These lubrication properties permit the drillingof wells having a significant vertical deviation, as is typical ofoff-shore or deep water drilling operations or when a horizontal well isdesired. In such highly deviated holes, torque and drag on the drillstring are a significant problem because the drill pipe lies against thelow side of the hole, and the risk of pipe sticking is high whenwater-based muds are used. In contrast, oil-based muds provide a thin,slick filter cake that helps to prevent pipe sticking, and thus the useof the oil-based mud can be justified.

Despite the many benefits of using oil-based muds, they havedisadvantages. In general, the use of oil-based drilling fluids and mudshave high initial and operational costs. These costs can be significantdepending on the depth of the hole to be drilled. However, the highercosts can often be justified if the oil-based drilling fluid preventsthe caving in or hole enlargement that can greatly increase drillingtime and costs.

Disposal of oil-coated cuttings is another primary concern, especiallyfor off-shore or deep-water drilling operations. In these latter cases,the cuttings must be either washed clean of the oil with a detergentsolution that also must be disposed, or the cuttings must be shippedback to shore for disposal in an environmentally safe manner. Anotherconsideration that must be taken into account is the local governmentalregulations that may restrict the use of oil-based drilling fluids andmuds for environmental reasons.

Oil-based muds typically contain some water, either from the formulationof the drilling fluid itself, or water may be intentionally added toaffect the properties of the drilling fluid or mud. In such water-in-oiltype emulsions, also known as invert emulsions, an emulsifier is used tostabilize the emulsion. In general, the invert emulsion may contain bothwater soluble and oil soluble emulsifying agents. Typical examples ofsuch emulsifiers include polyvalent metal soaps, fatty acids and fattyacid soaps, and other similar suitable compounds that should be known toone of ordinary skill in the art.

After any completion operations have been accomplished, removal offilter cake remaining on the sidewalls of the wellbore may be necessary.Although filter cake formation is essential to drilling operations, thefilter cake can be a significant impediment to the production ofhydrocarbon or other fluids from the well if, for example, the rockformation is plugged by the filter cake. Because filter cake is compact,it often adheres strongly to the formation and may not be readily orcompletely flushed out of the formation by fluid action alone.

The removal of filter cake has been conventionally achieved with waterbased treatments that include: an aqueous solution with an oxidizer(such as persulfate), a hydrochloric acid solution, organic (acetic,formic) acid, combinations of acids and oxidizers, and aqueous solutionscontaining enzymes. For example, the use of enzymes to remove filtercake is disclosed in U.S. Pat. No. 4,169,818. Chelating agents (e.g.,EDTA) have also been used to promote the dissolution of calciumcarbonate. According to traditional teachings, the oxidizer and enzymeattack the polymer fraction of the filter cake and the acids typicallyattack the carbonate fraction (and other minerals). Generally, oxidizersand enzymes are ineffective in breaking up the carbonate portion, andacid are ineffective on the polymer portions.

One of the most problematic issues facing filter cake removal involvesthe placement of the clean-up solutions. Because one of the more commoncomponents in a filter cake is calcium carbonate, a clean-up solutionwould ideally include hydrochloric acid, which reacts very quickly withcalcium carbonate. However, while effective in targeting calciumcarbonate, such a strong acid is also reactive with any calciumcarbonate in the formation (e.g., limestone), and can permeate into theformation.

The use of traditional emulsifiers and surfactants in the invertdrilling fluid systems that formed the filter cake can furthercomplicate the clean-up process in open-hole completion operations.Specifically, fluids using traditional surfactant and emulsifiermaterials may require the use of solvents and other surfactant washes topenetrate the filter cake and reverse the wettability of the filter cakeparticles. Invert emulsions drilling fluids that exhibit an acid inducedphase change reaction have been previously described in U.S. Pat. Nos.6,218,342, 6,790,811, and 6,806,233 and U.S. Patent Publication No.2004/0147404, the contents of which are incorporated by reference intheir entirety. The fluids disclosed in these references all contain oneform or another of an ethoxylated tertiary amine compound thatstabilizes the invert emulsion when it is not protonated. Uponprotonation of the amine compound, the invert emulsion reverses andbecomes a regular emulsion. In most cases, deprotonation of the aminecompound allows for the reformation of an invert emulsion. The clean-upof wells drilled with this invert emulsion drilling fluid may besimplified by using a wash fluid that contains acid in a concentrationsufficient to protonate the amine surfactant in the drilling fluid (andhence the filter cake). Thus, the presence of this amine surfactant inthe drilling fluid may control the phase state (i.e., invert versusregular emulsions) of the fluids in the well. Similarly, U.S. Pat. No.5,888,944 describes the use of an acid sensitive surfactant thatstabilizes the invert emulsion of the drilling fluid. Upon the additionof an acid in a wash fluid, for example, the surfactant immediatelyprotonates to break or invert the invert emulsion to an oil-in-watertype emulsion.

The problems of efficient well clean-up, stimulation, and completion area significant issue in all wells, and especially in open-hole horizontalwell completions. The productivity of a well is somewhat dependent oneffectively and efficiently removing the filter cake while minimizingthe potential of water blocking, plugging, or otherwise damaging thenatural flow channels of the formation, as well as those of thecompletion assembly. Thus there exists a continuing need for completionand displacement fluids that effectively clean the well bore and do notinhibit the ability of the formation to produce oil or gas once the wellis brought into production.

Accordingly, there exists a need for a displacement and clean-upsolution that will remove invert emulsion filter cake without damagingthe formation while allowing for easy placement of the solution in thewellbore and control of the phase state of the drilling fluids in thewell.

SUMMARY OF INVENTION

In one aspect, the present invention relates to a method of cleaning awellbore, wherein the wellbore has been drilled with an invert emulsiondrilling mud that forms an invert emulsion filter cake. The method mayinclude the steps of circulating a breaker fluid into the wellbore,where the breaker fluid includes an aqueous fluid, a water soluble polarorganic solvent, a hydrolysable ester of a carboxylic acid, and aweighting agent, wherein the hydrolysable ester is selected so that uponhydrolysis an organic acid is released and the invert emulsion of thefilter cake breaks.

In another aspect, the present invention relates to a method ofproducing a hydrocarbon from a formation. The method may include thesteps of drilling the formation with an invert emulsion drilling mud,performing at least one completion operation in the wellbore, emplacinga water-based breaker fluid in the wellbore, where the breaker fluid mayinclude an aqueous fluid, a water soluble polar organic solvent, ahydrolysable ester of a carboxylic acid, and a weighting agent, andshutting the well for a predetermined time to allow the hydrolysis ofthe ester and the breaking of the invert emulsion filter cake.

In yet another aspect, the present invention relates to a solution thatmay include may include an aqueous fluid, a water soluble polar organicsolvent, a hydrolysable ester of a carboxylic acid, and a weightingagent.

Other aspects and advantages of the invention will be apparent from thefollowing description and the appended claims.

DETAILED DESCRIPTION

In one aspect, embodiments disclosed herein are generally directed tochemical breaker and displacement fluids that are useful in thedrilling, completing, and working over of subterranean wells, preferablyoil and gas wells. The displacement and completion fluids may beselected from a water based fluid and an invert emulsion fluid. Theusefulness of the fluids disclosed herein is not dependent on the use ofethoxylated tertiary amines in the fluids used to drill the well. Thus,the broad applicability and usefulness of the fluids disclosed herein isgreatly enhanced. The water-based and invert emulsion displacement andcompletion fluids of the present invention are particularly useful inwells that are drilled with an invert emulsion drilling fluid that formsan invert emulsion filter cake in the well.

In one embodiment, the breaker fluid may be an invert emulsion fluidthat may include a non-oleaginous internal phase and an oleaginousexternal phase. The non-oleaginous internal phase may include a watersoluble polar organic solvent, a hydrolysable ester of a carboxylicacid; and optionally a weighting agent such as a high density brinesolution. The oleaginous external phase may include an oleaginous fluidsuch as diesel or other suitable hydrocarbon or synthetic oil, and anemulsifier. Optionally other components may include a viscosifyingagent, a wetting agent, and a cleaning agent.

The oleaginous fluid used for formulating the invert emulsion fluidsused in the practice of the present invention are liquids and are morepreferably a natural or synthetic oil and more preferably, theoleaginous fluid is selected from the group including diesel oil,mineral oil, such as polyolefins, polydiorganosiloxanes, siloxanes ororgano-siloxanes, and mixtures thereof. The concentration of theoleaginous fluid should be sufficient so that an invert emulsion formsand may be less than about 99% by volume of the invert emulsion.However, generally the amount of oleaginous fluid must be sufficient toform a stable emulsion when utilized as the continuous phase. In variousembodiments, the amount of oleaginous fluid at least about 30 percent,preferably at least about 40 percent, and more preferably at least about50 percent by volume of the total fluid. In one embodiment, the amountof oleaginous fluid is from about 30 to about 95 percent by volume andmore preferably from about 40 to about 90 percent by volume of theinvert emulsion fluid.

The non-oleaginous fluid also used in the formulation of the invertemulsion fluids is a liquid and preferably is an aqueous liquid. Morepreferably, the non-oleaginous fluid may be selected from the groupincluding sea water, a brine containing organic and/or inorganicdissolved salts, liquids containing water-miscible organic compounds andcombinations thereof. The amount of the non-oleaginous fluid istypically less than the theoretical limit needed for forming an invertemulsion. In various embodiments, the amount of non-oleaginous liquid isat least about 1, preferably at least about 5, and more preferablygreater than about 10 percent by volume of the total fluid.Correspondingly, the amount of the non-oleaginous fluid should not be sogreat that it cannot be dispersed in the oleaginous phase. Thus, in oneembodiment, the amount of non-oleaginous fluid is less than about 70% byvolume and preferably from about 1% to about 70% by volume. In anotherembodiment, the non-oleaginous fluid is preferably from about 10% toabout 60% by volume of the invert emulsion fluid.

In another embodiment, the breaker fluid may be a water based fluid thatmay include an aqueous fluid. Additionally, the water based fluid mayinclude a water soluble polar organic solvent, a hydrolysable ester of acarboxylic acid; and optionally a weighting agent such as a high densitybrine solution. The aqueous fluid used in the water based fluids may beselected from the group including sea water, a brine containing organicand/or inorganic dissolved salts, liquids containing water-miscibleorganic compounds and combinations thereof.

The water soluble polar organic solvent should be at least partiallysoluble in a oleaginous fluid, but should also have partial solubilityin an aqueous fluid. The polar organic solvent component of the presentinvention may be a mono-hydric, di-hydric or poly-hydric alcohol or amono-hydric, di-hydric, or poly-hydric alcohol having poly-functionalgroups. Examples of such compounds include aliphatic diols (i.e.,glycols, 1,3-diols, 1,4-diols, etc.), aliphatic poly-ols (i.e., tri-ols,tetra-ols, etc.), polyglycols (i.e., polyethylenepropylene glycols,polypropylene glycol, polyethylene glycol, etc.), glycol ethers (i.e.,diethylene glycol ether, triethylene glycol ether, polyethylene glycolether, etc.) and other such similar compounds that may be found usefulin the practice of the present invention. In one preferred embodiment,the water soluble organic solvent is a glycol or glycol ether, such asethylene glycol mono-butyl ether (EGMBE). Other glycols or glycol ethersmay be used in the present invention so long as they are at leastpartially miscible with water.

The hydrolysable ester should be selected so that the time to achievehydrolysis is predetermined on the known downhole conditions, such astemperature. It is well known in the art that temperature, as well asthe presence of a hydroxide ion source, has a substantial impact on therate of hydrolysis of esters. For a given acid, for example formic aid,one of skill in the art can conduct simple studies to determine the timeto hydrolysis at a given temperature. It is also well known that as thelength of the alcohol portion of the ester increases, the rate ofhydrolysis decreases. Thus, by systematically varying the length andbranching of the alcohol portion of the ester, the rate of release ofthe formic acid can be controlled and thus the breaking of the emulsionof an invert emulsion filter cake can be predetermined. In one preferredembodiment, the hydrolysable ester of a carboxylic acid is a formic acidester of a C4 to C30 alcohol. In one embodiment, the hydrolysable esterof the carboxylic acid comprises from about 5 to 50 volume percent of awater-based breaker fluid, and preferably from about 20 to 40 volumepercent. In another embodiment, the hydrolysable ester of the carboxylicacid comprises from about 20 to about 60 volume percent of an invertemulsion-based breaker fluid, preferably, greater than 30 volumepercent. One example of a suitable hydrolysable ester of a carboxylicacid is available from Shrieve Chemical Group (The Woodlands, Tex.)under the name Break-910.

In the present illustrative embodiment, the weighting agent ispreferably a high density brine containing salts of alkali and alkalineearth metals. For example, brines formulated with high concentrations ofsodium potassium, or calcium salts of the halides, formate, acetate,nitrate, and the like; cesium salts of formate, acetate, nitrate, andthe like, as well as other compounds that should be well known to one ofskill in the art, can be used as solids free weighting agents. Theselection of a weighting agent may partially depend the desired densityof the breaker fluid, as known by one of ordinary skill in the art.

The emulsifier used in the invert emulsion breaker fluid should beselected so as to form a stable invert emulsion that breaks with timeand/or upon hydrolysis of the ester. That is to say, when the pH of theinvert emulsion's non-oleaginous phase changes, the emulsifier'shydrophilic-lipophilic balance (HLB) value is sufficiently shifted todestabilize the invert emulsion. The HLB value indicates the polarity ofthe molecules in a range of 1 to 40 that increases with increasinghydrophilicity of the emulsifier. Given the large variety of invertemulsion emulsifiers available, one of ordinary skill in the art needonly do a routine screen of emulsifiers by forming an invert emulsionand adding a small amount of formic acid to see if the emulsion breaks.Preferred emulsifiers may include VERSAWET™ and VERSACOAT™, which arecommercially available from M-I L.L.C., Houston, Tex. Alternatively, anamine-based acid sensitive emulsifier such as those described in U.S.Pat. Nos. 6,218,342, 6,790,811, and 6,806,233, the contents of which areincorporated by reference herein, may be used.

Both the invert emulsion fluids and water based fluids of the presentinvention may further contain additional chemicals depending upon theend use of the fluid so long as they do not interfere with thefunctionality of the fluids (particularly the emulsion when using invertemulsion displacement fluids) described herein. For example, wettingagents, organophilic clays, viscosifiers, fluid loss control agents,surfactants, dispersants, interfacial tension reducers, pH buffers,mutual solvents, thinners, thinning agents and cleaning agents may beadded to the fluid compositions of this invention for additionalfunctional properties. The addition of such agents should be well knownto one of ordinary skill in the art of formulating drilling fluids andmuds.

Wetting agents that may be suitable for use in this invention includecrude tall oil, oxidized crude tall oil, surfactants, organic phosphateesters, modified imidazolines and amidoamines, alkyl aromatic sulfatesand sulfonates, and the like, and combinations or derivatives of these.However, when used with the invert emulsion fluid, the use of fatty acidwetting agents should be minimized so as to not adversely affect thereversibility of the invert emulsion disclosed herein. Faze-Wet™,VersaCoat™, SureWet™, Versawet™ and Versawet™ NS are examples ofcommercially available wetting agents manufactured and distributed byM-I L.L.C. that may be used in the fluids disclosed herein. Silwet L-77,L-7001, L7605, and L-7622 are examples of commercially availablesurfactants and wetting agents manufactured and distributed by GeneralElectric Company (Wilton, Conn.).

Organophilic clays, normally amine treated clays, may be useful asviscosifiers and/or emulsion stabilizers in the fluid composition of thepresent invention. Other viscosifiers, such as oil soluble polymers,polyamide resins, polycarboxylic acids and soaps can also be used. Theamount of viscosifier used in the composition can vary upon the end useof the composition. However, normally about 0.1% to 6% by weight rangeis sufficient for most applications. VG-69™ and VG-PLUS™ are organoclaymaterials distributed by M-I, L.L.C., Houston, Tex., and Versa-HRP™ is apolyamide resin material manufactured and distributed by M-I, L.L.C.,that may be used in this invention. In some embodiments, the viscosityof the displacement fluids is sufficiently high such that thedisplacement fluid may act as its own displacement pill in a well.

Suitable thinners that may be used in the breaker fluids disclosedherein include, for example, lignosulfonates, modified lignosulfonates,polyphosphates, tannins, and low molecular weight polyacrylates.Thinners are typically added to a drilling fluid to reduce flowresistance and control gelation tendencies. Other functions performed bythinners include reducing filtration and filter cake thickness,counteracting the effects of salts, minimizing the effects of water onthe formations drilled, emulsifying oil in water, and stabilizing mudproperties at elevated temperatures.

The inclusion of cleaning agents in the fluids disclosed herein shouldbe well known to one of skill in the art. A wide variety of syntheticand natural product derived cleaning agents may be used. For example, acommon natural product derived cleaning agent is d-limonene. Thecleaning ability of d-limonene in well drilling applications isdisclosed in U.S. Pat. No. 4,533,487, and in combination with variousspecialty surfactants in U.S. Pat. No. 5,458,197, the contents of whichare incorporated herein.

The methods used in preparing both the water-based and invert emulsionbreaker fluids utilized in the methods of the present disclosure are notcritical. Specifically, with respect to the invert emulsion fluids,conventional methods can be used to prepare the invert emulsion fluidsin a manner analogous to those normally used to prepare oil-baseddrilling fluids. In one representative procedure, a desired quantity ofoleaginous fluid, such as diesel oil, is mixed with the selectedemulsifier, viscosifying agent, and wetting agent. The internalnon-oleaginous phase is prepared by combining the polar organicco-solvent and the hydrolysable ester into the selected brine withcontinuous mixing. An invert emulsion of the present invention is formedby vigorously agitating, mixing, or shearing the oleaginous fluid andthe non-oleaginous fluid.

The breaker fluids disclosed herein may also be used in variousembodiments as a displacement fluid and/or a wash fluid. As used herein,a displacement fluid is typically used to physically push another fluidout of the wellbore, and a wash fluid typically contains a surfactantand may be used to physically and chemically remove drilling fluidreside from downhole tubulars.

In one embodiment, a breaker fluid may be in a method of cleaning awellbore that has been drilled with an invert emulsion drilling mud, andthus has an invert emulsion filter cake formed thereon. The breakerfluid may be circulated into the wellbore, contacting the invertemulsion filter cake. The hydrolysable ester contained within thebreaker fluid may hydrolyze to release an organic acid and break theinvert emulsion of the filter cake. The breaker fluid may be circulatedin the wellbore that has not produced any hydrocarbons. Alternatively,if a wellbore that has already begun production of hydrocarbons isbelieved to be impaired by any residual filter cake left in the wellfollowing the drilling operations, a breaker fluid of the presentinvention may be used to clean the wellbore.

In another embodiment, the water-based breaker fluid and/or the invertemulsion breaker fluid may also be used as a displacement fluid to pushfluids out of a wellbore. An invert emulsion breaker fluid may act as apush pill or displacement fluid to effectively displace the invertemulsion drilling mud. A water based breaker fluid may act as adisplacement fluid to effectively displace brine from the wellbore.

In yet another embodiment, the water-based breaker fluid and/or invertemulsion breaker fluid may further be used as a wash fluid to physicallyand/or chemically remove the invert emulsion filter cake once the filtercake has been disaggregated by the breaker system.

In another embodiment, a breaker fluid (either a water-based or aninvert emulsion fluid) disclosed herein may be used in the production ofhydrocarbons from a formation. Following the drilling of a formationwith an invert emulsion drilling mud, at least one completion operationmay be performed on the well. A breaker fluid may then be circulated inthe well, and the well may be shut for a predetermined time to allow thehydrolysis of the ester and the breaking of the invert emulsion of thefiltercake formed from the drilling mud. In another embodiment,formation fluids may then enter the well and production of the formationfluids may ensue.

In some embodiments, the breaker fluid may be circulated in the wellboreduring or after the performance of the at least one completionoperation. In other embodiments, the breaker fluid may be circulatedeither after a completion operation or after production of formationfluids has commenced to destroy the integrity of and clean up residualconventional or reversible invert emulsion fluids remaining insidecasing or liner.

Generally, a well is often “completed” to allow for the flow ofhydrocarbons out of the formation and up to the surface. As used herein,completion processes may include one or more of the strengthening thewell hole with casing, evaluating the pressure and temperature of theformation, and installing the proper completion equipment to ensure anefficient flow of hydrocarbons out of the well or in the case of aninjector well, to allow for the injection of gas or water.

In one embodiment, a breaker fluid as disclosed herein may be used in acased hole to remove any residual oil based mud left in the hole duringany drilling and/or displacement processes. Well casing may consist of aseries of metal tubes installed in the freshly drilled hole. Casingserves to strengthen the sides of the well hole, ensure that no oil ornatural gas seeps out of the well hole as it is brought to the surface,and to keep other fluids or gases from seeping into the formationthrough the well.

Completion operations, as used herein, may specifically include openhole completions, conventional perforated completions, sand exclusioncompletions, permanent completions, multiple zone completions, anddrainhole completions, as known in the art. A completed wellbore maycontain at least one of a slotted liner, a predrilled liner, a wirewrapped screen, an exapandable screen, a sand screen filter, a open holegravel pack, or casing.

Another embodiment of the present invention involves a method ofcleaning up a well bore drilled with the invert emulsion drilling fluiddescribed above. In one such illustrative embodiment, the methodinvolves circulating a breaker fluid disclosed herein in a wellbore,which as been drilled to a larger size (i.e., under reamed) with aninvert emulsion drilling mud, and then shutting in the well for apredetermined amount of time to allow the hydrolysis of the ester totake place. Upon hydrolysis of the ester, the invert emulsion breaks,thus forming two phases, and oil phase and a water phase. These twophases can be easily produced from the well bore upon initiation ofproduction and thus the residual drilling fluid is easily washed out ofthe well bore.

The fluids disclosed herein may also be used in a wellbore where ascreen is to be put in place down hole. After a hole is under-reamed towiden the diameter of the hole, drilling string may be removed andreplaced with production tubing having a desired sand screen.Alternatively, an expandable tubular sand screen may be expanded inplace or a gravel pack may be placed in the well. Breaker fluids maythen be placed in the well, and the well is then shut in to allow forthe hydrolysis of the ester to take place. Upon hydrolysis of the ester,the invert emulsion breaks thus forming two phases, an oil phase and awater phase. These two phases can be easily produced from the wellboreupon initiation of production and thus the residual drilling fluid iseasily washed out of the wellbore.

The amount of delay between the time when a breaker fluid according tothe present invention is introduced to a well drilled with an invertemulsion drilling fluid and the time when the hydrolysable ester of acarboxylic acid hydrolyzes, releasing acid to break the invert emulsionfilter cake may depend on several variables. The rate of hydrolysis ofthe hydrolysable ester may be dependent upon the downhole temperature,concentration, pH, amount of available water, filter cake composition,etc. In one embodiment, there may be preferable a downhole temperatureof less than 270° F. for the applicability of the displacement fluids ofthe present invention in a given well.

However, depending on the downhole conditions, the breaker fluidformulation and thus the fluid's chemical properties may be varied so asto allow for a desirable and controllable amount of delay prior to thebreaking of invert emulsion filter cake for a particular application. Inone embodiment, the amount of delay for an invert emulsion filter caketo be broken with a water-based displacement fluid according to thepresent invention may be greater than I hour. In various otherembodiments, the amount of delay for an invert emulsion filter cake tobe broken with a water-based displacement fluid according to the presentinvention may be greater than 3 hours, 5 hours, or 10 hours.

In another embodiment, the amount of delay for an invert emulsion filtercake to be broken with an invert emulsion displacement fluid may begreater than 15 hours. In various other embodiments, the amount of delayfor an invert emulsion filter cake to be broken with an invert emulsiondisplacement fluid may be greater than 24 hours, 48 hours, or 72 hours.

The following examples are provided to further illustrate theapplication and the use of the methods and compositions of the presentinvention.

EXAMPLES

The following examples were used to test the effectiveness of thedisplacement and clean-up solutions disclosed herein:

Example 1

An invert emulsion drilling mud, Fazepro™, commercially available fromM-I, L.L.C. (Houston, Tex.), was heat aged by hot rolling for 16 hoursat 200° F. and exhibited the following properties, as shown below inTable 1. TABLE 1 Heat-aged @ 200° F.-16 hrs - Rheology @ 120° F. 600 RPM118 300 RPM 69 200 RPM 50 100 RPM 29  6 RPM 6  3 RPM 4 Gels 10″  6lbs/100 ft² Gels 10′ 10 lbs/100 ft² Plastic Viscosity 49 cP Yield Point20 lbs/100 ft² Electrical Stability 38 volts

Filter cakes built from the above invert emulsion drilling fluid weresubjected to a modified High Temperature High Pressure (HTHP) Filtrationtest. The HTHP Filtration test uses a HTHP cell fitted with a fritteddisc as a porous medium, on which a filter cake is built. In thisexample, the filter cakes were built on 35 micron disks. Uponapplication of 500 psi at 200° F. to the disks of filter cake, effluentwas collected as shown in Table 2. TABLE 2 Time Disk 1 (mL) Disk 2 (mL)Spurt 1.4 1.4 1 min 0.2 0.2 4 min 0.6 0.6 9 min 0.8 0.8 16 min 1.0 1.225 min 1.2 1.4 30 min 1.2 1.4 36 min 1.2 1.6 40 min 1.4 1.6 1 hr 2 3.4 2hr 2 4 3 hr 4.4 4.6 4 hr 5.4 5.6

A water based displacement breaker fluid was formulated having thefollowing components, all of which are commercially available, as shownbelow in Table 3. TABLE 3 Component Fluid 1 Fluid 2 10.25 ppg CalciumChloride 235.4 ppb 235.4 ppb Acetic Acid 0.2 ppb 0.2 ppb EGMBE 31.9 ppb31.9 ppb Break-910 141.1 ppb — Fazemul ™ 0.8 ppb 0.8 ppb

Displacement fluids 1 and 2, formulated as shown in Table 3, were addedto filter cakes disks 1 and 2, formulated from a Fazepro™ drillingfluid, and subjected to a modified HTHP Filtration test. Uponapplication of an initial pressure of 250 psi at 200° F. to the disks offilter cake having displacement fluids 1 and 2 poured thereon, effluentwas collected as shown in Table 4 below. After 250 psi was applied for40 minutes, the applied pressure was decreased to 25 psi. When a steadystream of effluent resulted through the disk, the test was concluded.From Table 4, it can be observed that Fluid 1, which contained ahydrolysable ester of a carboxylic acid, achieved a break-through of thefiltrate at 16 minutes, while Fluid 2, which did not include the ester,did not. From an initial injection of 200 ml sea water of 8.42 sec and afinal injection of 200 ml sea water/fluid 1 of 9.28 sec, a return toinjection rate of 90.7% was calculated for this test. TABLE 4 Time Disk1 (mL) Disk 2 (mL) Spurt 0.2 0.2 1 min 0.2 0.2 4 min 3.0 0.2 9 min 10.80.2 16 min 56 0.2 25 min — 0.2 30 min — 0.2 36 min — 0.2 40 min — 0.2 1hr — 0.2 2 hr — 0.2 3 hr — — 4 hr — —

Example 2

An invert emulsion drilling mud, Fazepro , commercially available fromM-I, L.L.C. (Houston, Tex.), was heat aged by hot rolling for 4 hours at200° F. and exhibited the following properties, as shown below in Table5. TABLE 5 Heat-aged @ 200° F.-4 hrs - Rheology @ 120° F. 600 RPM 112300 RPM 65 200 RPM 48 100 RPM 28  6 RPM 5  3 RPM 4 Gels 10″  6 lbs/100ft² Gels 10′ 11 lbs/100 ft² Plastic Viscosity 47 cP Yield Point 18lbs/100 ft²

Filter cakes built from the above invert emulsion drilling fluid werebuilt on 35 micron disks and subjected to a modified HTHP Filtrationtest. Upon application of 500 psi at 200° F. to the disks of filtercake, effluent was collected as shown in Table 6. TABLE 6 Time Disk 3(mL) Disk 4 (mL) Spurt 2.2 2.4  1 min 0.8 0.6  4 min 1.4 1.2  9 min 1.61.6 16 min 1.8 2.0 25 min 2.4 2.4 30 min 2.6 2.6 36 min 2.8 2.8 ModifiedHTHP 7.4 7.6 Fluid Loss  4 hr (incl. spurt) 10.2 11.0

A water based displacement fluid was formulated having the followingcomponents, all of which are commercially available, as shown below inTable 7. TABLE 7 Component Fluid 1 Fluid 2 10.25 ppg CaCl₂ 235.4 g 235.4g EGMBE 31.9 g 31.9 g Glacial Acetic Acid 0.2 g 0.2 g Break-910 141.1 g141.1 g Fazemul ™ 0.8 g 0.8 g KCl — 4.0 g

Displacement fluids 3 and 4, formulated as shown in Table 7, were addedto filter cakes disks 3 and 4, formulated from the Fazepro™ drillingfluid, and subjected to a modified HTHP Filtration test. Uponapplication of an initial pressure of 400 psi at 200° F. to the disks offilter cake having displacement fluids 3 and 4 poured thereon, effluentwas collected as shown in Table 8 below. After 400 psi was applied for40 minutes, the applied pressure was decreased to 50 psi. When a steadystream of effluent resulted through the disk, the cell containing thedisk was closed and allowed to soak for 24 hours at 200° F. From Table9, it can be observed that Fluid 3 achieved a steady stream of effluentimmediately and Fluid 4 achieved a steady stream after 9 minutes. TABLE9 Time Disk 3 (mL) Disk 4 (mL) Spurt 9.8 0 1 min — 2 4 min — 4 9 min —11

Further, while reference has been made to particular applications forthe displacement and completion fluids of the present invention, it isexpressly within the scope of the present invention that these fluidsmay be in used in a variety of well applications. Specifically, thefluids of the present invention may be used in both producing andinjection wells, and may have further application in remedial clean-upof wells.

Advantageously, the present invention provides for a wellbore fluid thatmay break the emulsion of an invert emulsion filter cake and effectivelyremove such invert emulsion filter cake without inflicting damage on thesurrounding formation. Displacement and completion fluids according tothe present invention may exhibit high-viscosity indices such that theymay behave as a high viscosity pill in the well completion process.Furthermore, a delay in the dissolution of the filter cake may beachieved by controlling the effectiveness and reactivity of the chemicalbreakers. The chemical properties of the displacement and breaker fluidsdisclosed herein may allow for the degradation of the emulsion of theinvert emulsion filter cake and the dissolution of acid soluble bridgingmaterials in the filter cake. Additionally, displacement and breakerfluids disclosed herein may be effectively used with either conventionalinvert emulsion or reversible invert emulsion drilling fluid filtercakes.

While the invention has been described with respect to a limited numberof embodiments, those skilled in the art, having benefit of thisdisclosure, will appreciate that other embodiments can be devised whichdo not depart from the scope of the invention as disclosed herein.Accordingly, the scope of the invention should be limited only by theattached claims.

1. A method of cleaning a wellbore, wherein the wellbore has beendrilled with an invert emulsion drilling mud that forms an invertemulsion filter cake, the method comprising: circulating a breaker fluidinto the wellbore, the breaker fluid comprising: an aqueous fluid; awater soluble polar organic solvent; a hydrolysable ester of acarboxylic acid; and a weighting agent; and wherein the hydrolysableester is selected so that upon hydrolysis an organic acid is releasedand the invert emulsion of the filter cake breaks.
 2. The method ofclaim 1, wherein the water soluble polar organic solvent is a glycol orglycol ether.
 3. The method of claim 2, wherein the water soluble polarorganic solvent is ethylene glycol mono-butyl ether.
 4. The method ofclaim 1, wherein the hydrolysable ester of the carboxylic acid is aformic acid ester of a C4 to C30 alcohol.
 5. The method of claim 1,wherein the weighting agent comprises at least one of halide and formatesalts of alkali and alkaline earth metals.
 6. The method of claim 1,further comprising: displacing the aqueous fluid from the wellbore. 7.The method of claim 1, further comprising: removing the broken invertemulsion filter cake from the wellbore.
 8. A method of producing ahydrocarbon from a formation, the method comprising: drilling theformation with an invert emulsion drilling mud; performing at least onecompletion operation in the wellbore; emplacing a water-based breakerfluid in the wellbore, the breaker fluid comprising: an aqueous fluid; awater soluble polar organic solvent; a hydrolysable ester of acarboxylic acid; and a weighting agent; and shutting the well for apredetermined time to allow the hydrolysis of the ester and the breakingof the invert emulsion filter cake.
 9. The method of claim 8, furthercomprising: allowing the formation fluids to enter into the well; andproducing fluids from the well.
 10. The method of claim 9, wherein theemplacing the breaker fluid occurs after producing the fluids from thewell.
 11. The method of claim 8, wherein the emplacing the breaker fluidoccurs simultaneous as performing the at least one completion operation.12. The method of claim 8, wherein the emplacing the breaker fluidoccurs after performing the at least one completion operation.
 13. Themethod of claim 8, wherein the completed wellbore contains at least oneof a slotted liner, a predrilled liner, a wire wrapped screen, anexapandable screen, a sand screen filter, a open hole gravel pack, andcasing.
 14. The method of claim 8, wherein the water soluble polarorganic solvent is a glycol or glycol ether.
 15. The method of claim 14,wherein the water soluble polar organic solvent is ethylene glycolmono-butyl ether.
 16. The method of claim 8, wherein the hydrolysableester of the carboxylic acid is a formic acid ester of a C4 to C30alcohol.
 17. A solution, comprising: an aqueous fluid; a water solublepolar organic solvent; a hydrolysable ester of a carboxylic acid; and aweighting agent.
 18. The solution of claim 17, wherein the water solublepolar organic solvent is a glycol or glycol ether.
 19. The solution ofclaim 18, wherein the water soluble polar organic solvent is ethyleneglycol mono-butyl ether.
 20. The solution of claim 17, wherein thehydrolysable ester of the carboxylic acid is a formic acid ester of a C4to C30 alcohol.
 21. The solution of claim 17, wherein the weightingagent is a brine containing salts of alkali and alkaline earth metals.22. The solution of claim 17, further comprising: at least one selectedfrom a wetting agent, a cleaning agent, a viscosifying agent, a fluidloss control agent, a dispersant, an interfacial tension reducer, a pHbuffer, a thinner, and a surfactant.
 23. The solution of claim 17,wherein the aqueous fluid is selected from fresh water, sea water, abrine containing organic and/or inorganic dissolved salts, liquidscontaining water-miscible organic compounds and combinations thereof.24. The solution of claim 17, wherein the hydrolysable ester of thecarboxylic acid comprises from about 5 to about 50 volume percent of thesolution.